Permeability is the most important single property of a hydrocarbon reservoir rock. Rock properties which influence permeability include particle size, particle packing, particle size distribution, grain angularity, and the degree of lithification (cementation and consolidation). The permeability of a reservoir rock, usually expressed in "millidarcys", may be defined as the fluid conductivity within the interconnected porework of a porous media. Specific permeability of a porous media refers to a permeability measured with a single fluid at 100% saturation of that fluid present in the pore spaces. The effective permeability of a porous media applies to the permeability of each phase at a specified saturation when two or more phases are present in the pore spaces. Effective permeabilities are always lower than specific permeabilities because the presence of other phases inhibits the ability of a specific phase to flow.
The permeability of a reservoir rock is susceptible to two distinct types of damage. One type of damage is caused by the expansion and/or migration of clay particles and a second type of permeability damage is caused by specific and particular hydrocarbon production practices which are independent of the mineralogy and texture of the rock. Permeability damage around a well bore will lower the productivity of completed wells. In secondary or tertiary recovery processes, permeability maintenance through reservoir clay control can mean the difference between economic success or failure.
The term clay is used as a rock term and as a particle size term. As a particle size term clay refers to particles having an equivalent Stokes diameter of less than two microns. As a rock term, the term clay mineral refers to silicate minerals with a crystal structure of the two layer type (e.g. kaolinite) of the three layer type (e.g. montmorillonite) in which silicon has a tetrahedral coordination with respect to oxygen (i.e. the tetrahedral layer) while aluminum, iron, magnesium, manganese and other such ions have octahedral coordination with respect to oxygen (i.e. the octahedral layer.) Exchangeable cations may exist in thermal motion on the surfaces of the silicate layers in an equivalent amount as determined by the excess negative charge existing within each composite layer. For the purposes of this invention, the term clay is deemed to include both rock and particle size meanings.
The kind of ion (either exchangeable cation or anion) and the distance of the ion from the clay surface greatly influences the behavior of clay colloids. The higher the charge of a cation the greater the tenacity with which it is adsorbed on a clay particle. Sodium ion relative to calcium ion (with a positive charge of 2) is held by the clay with less bonding energy partially accounting for clay damage in reservoirs containing sodium chloride brines whose concentration changes with reservoir fluid changes.
The behavior of clay colloids in fluid environments is most often explained and predicated on the basis of the electrical double layer, which consists of the surface particle charge of the clay and an equivalent amount of ionic charge which is accumulated in the liquid near the particle surface. The thickness of the double layer depends upon the concentration and charge of electrolytes in the solution surrounding the clay particle. In order to maintain the permeability of the reservoir rock, it is desirable to suppress the thickness of the double layer and allow two negatively charged particles to come into close proximity.
High concentrations of electrolytes in the fluids such as sodium chloride brines will depress the thickness of the electrical double layer but as the concentration of salt in the fluid decreases the double layer expands causing the undesirable expansion of layers and movement of the clay particles. The first stages of clay expansion can involve pressures of up to 60,000 psi (van Olphen, 1963). Prevention of such pressures as accomplished in this invention is a significant factor in controlling the permeability and structural competence of reservoirs lithified by clay cements.
The term shale refers to a sedimentary rock composed primarily of clay minerals such as chlorite, kaolinite, mica, illite, montmorillonite, etc., which have particle size diameters of less than two microns. Shale is not considered to be a porous hydrocarbon reservoir rock and is not the type of rock to be treated by the inventive method.
Many hydrocarbon bearing formations contain relatively thin zones of sands (with porosity development and hydrocarbon saturation) separated by shale streaks. The thin zones contain in addition to quartz and feldspar minerals, varying percentages of less than two micron in diameter clay minerals which partially accounts for the natural low permeability because the clay-sized minerals tend to block flow channels. For example, the natural permeability of such "tight" formations may be less than one millidarcy and the porosity may be less than 10%. In order to produce hydrocarbons from such rocks it is desirable to propagate vertical and or horizontal fractures to interconnect the thin zones of sand and some cases to extend the fractures as far as 4000 feet on either side of the well bore. One such method of creating artificial fissures and thereby increasing the pore space and permeability is known as hydraulic fracturing stimulation. Such a stimulation involves injecting a fluid under pressure down a well bore and into a hydrocarbon bearing formation in order to overcome native rock stress and to cause material failure (fracture) of the porous media. Many such stimulation attempts have been unsuccessful because the clay sized components are pushed to the furthermost extremities of the artificial fissures and upon placing the well on production, the clays attempt to migrate to the well bore and eventually become restricted damaging permeability and well productivity. In addition to migration, clays existing within the reservoir rock may adsorb water or other fluids and expand to block flow channels. Because of the abundance of clay-sized particles in many "tight" reservoirs, adequate clay control is a foremost consideration in selecting a fluid for use in stimulation treatments.
Reservoir rocks younger in age than Cretaceous are commonly unconsolidated or semiconsolidated. Improper well completion or production techniques frequently result in damage to the intergranular clay components which serve as lithifying agents. Such clay damage creates stress in the rock and causes it to become incompetent around the well bore. Movement of large sand sized particles and rearrangement of the pore geometry causes serious reductions in permeability. Acid treatment to dissolve clays usually results in further intrusion of clay sized particles ("formation fines") and even greater reductions in permeability. Furthermore, regular mud acid (i.e. a mixture of hydrochloric and hydrofluoric) can dissolve clays only within a few inches of the well bore. A method of formation control through permeability maintenance and clay control as taught in this inventive method is needed in conjunction with acid stimulation of many reservoir rocks.
Although the inventive method is useful in maintaining the permeability of porous rocks in general, it is particularly applicable to and thus will be primarily described in connection with the improvement of hydrocarbon recovery through the stabilization and the maintenance of the permeability of porous rocks encountered in the production of oil and gas.